1. Field of the Invention
The present invention relates generally to a petroleum well, and in particular to a petroleum well having a downhole measurement and control system for optimally controlling production of the well or the field in which the well is situated.
2. Description of Related Art
Gas lift is widely employed to generate artificial lift in oil wells that have insufficient reservoir pressure to drive formation fluids to the surface. Gas is supplied to the well by surface compressors which connect through an injection control valve to the annular space between the production tubing and the casing. The gas flows down this annulus to a gas lift valve which connects the annulus between the tubing and the casing to the interior of the tubing. The gas lift valve is located just above the production zone, and the lift is generated by the combination of reduced density caused by gas bubbles in the fluid column filling the tubing, and by entrained flow of the fluids by the rising bubble stream.
A variety of flow regimes in the tubing are recognized, and are determined by the flow rate at the gas lift valve. The gas bubbles in the tubing decompress as they rise in the tubing since the head pressure of the fluid column above drops as the bubbles rise. This to determining the flow regime, such as fluid column height, fluid decompression causes the bubbles to expand, so that the flow regimes within the tubing vary up the tubing, depending on the volumetric ratio of bubbles to liquid. Other factors contribute composition and phases present, tubing diameter, depth of well, temperature, back pressure set by the production control valve, and physical characteristics of the surface collection system.
The rate of injection at the gas lift valve is determined by the pressure difference across the valve, and its orifice size. On the annulus side the pressure is determined by the gas supply flow rate and pressure at the surface connection. On the tubing interior side of the gas lift valve, the pressure is determined by a number of factors, notably the static head of the fluid column above the valve, the flow rate of fluids up the tubing, the formation pressure, and the inflow rate in the production zone. Conventionally the orifice size of the gas lift valve is preset by selection at the time the valve is installed, and cannot be changed thereafter without changing the valve, which requires that the well be taken out of production.
Generally speaking, production from a well increases monotonically and continuously as the injection rate of lift gas increases, but the lift efficiency measured as the ratio of produced liquids to lift gas used varies significantly as the flow regime changes, and becomes low at higher gas injection rates especially if annular flow is induced. The specific numerical relationship between gas injection rate and production rate varies significantly from well to well, and also evolves over time even for a specific well as fluids are withdrawn from the reservoir or inflow conditions from the formation change.
The ongoing supply of compressed lift gas is a major determinant of production cost. Thus the relationship between lift gas injection rate and liquid production rate for a specific well is important, since this determines the real cost of liquids delivered to the surface. Optimizing the lift gas injection rate to minimize production cost is thus of direct value, but generally this optimization can only be approximated since the relationship between injection rate and production rate cannot be monitored in real time, and since there is only an indirect relationship between annulus pressure, determined by lift gas injection rate, and the resulting volumetric gas flow rate at the gas lift valve.
The annulus between the surface and the gas lift valve comprises a large volume which acts as a reservoir of compressed gas. Consequently there is significant delay between changing the flow of lift gas at the surface, and the corresponding change in annulus pressure which determines the injection rate at the gas lift valve downhole. Surface measurements of fluid flow rates and composition also exhibit delays which may be of the order of hours, the transit time for fluids from the production zones to the wellhead. These sources of time latency effectively prevent real-time, closed-loop control of production using gas lift.
Gas lift exhibits an instability termed “heading” if the gas flow rate is lowered below a certain threshold in attempts to either conserve lift gas, or reduce production rate. Heading is caused by a positive-feedback interaction between bottom-hole pressure in the producing zone, and flow rate through the gas lift valve which is determined by the pressure differential between the annulus and the bottom-hole pressure. As the lift gas injection rate is reduced by lowering the annulus pressure, bottom-hole pressure increases as flow from the formation into the well dwindles. This increase in bottom-hole pressure reduces the pressure differential across the gas-lift valve, further reducing the lift gas injection rate and therefore further reducing the withdrawal rate of fluids from the formation. The consequence is cyclic “heading” or surging which eventually leads to cessation of all fluid flow and the death of the well.
An important issue with heading is that the long latency between changes in bottom hole conditions and their consequences as visible production rate fluctuations at the surface makes recovery from heading difficult once it has been initiated. The existing strategy to maintain flow stability is to hold the injection gas flow rate safely above the minimum which is expected to initiate heading, whether or not this leads to the desired production rate from the well.
Under conditions of very low reservoir production, it may become necessary to operate with intermittent gas lift in which gas injection is cyclic. In this mode the gas lift valve is completely closed at the start of the cycle, and reservoir flow into the tubing occurs through a check valve at or near the bottom of the tubing. After sufficient time has elapsed to allow the fluid level in the tubing to have risen above the lift gas valve, this valve is snapped open to allow fast injection of a gas bubble which drives the fluid above it up the tubing. When the slug of fluids has been ejected at the well head, the lift gas valve closes, and the cycle repeats. The check valve prevents produced fluids from being driven back into the formation during the lift phase of the cycle.
Intermittent gas lift is considered undesirable for a number of reasons. The intermittent demand for a high flow of lift gas is hard on compressors, which operate best against a steady demand. To mitigate this factor accumulators may be used to store gas awaiting the next lift cycle, but these are a capital cost item with ongoing maintenance, and at best a partial solution. The high intermittent flow requires oversize piping between the compressor station and the dependent wells, and the cyclic load on the piping is mechanically stressful.
It would, therefore, be a significant advance in the operation of petroleum wells if a real-time method for determining the gas lift injection rate and the production fluid flow rate were provided. It would also be a significant advance if real-time monitoring of “heading” conditions were provided.
All references cited herein are incorporated by reference to the maximum extent allowable by law. To the extent a reference may not be fully incorporated herein, it is incorporated by reference for background purposes and indicative of the knowledge of one of ordinary skill in the art.